Xcel Energy 2012 Year End Earnings Report

Xcel Energy 2012 Year End Earnings Report
*Ongoing 2012 earnings per share were $1.82 compared with $1.72 per share
in 2011.
*GAAP (generally accepted accounting principles) 2012 earnings per share
were $1.85 compared with $1.72 per share in 2011.
*Xcel Energy reaffirms 2013 earnings guidance of $1.85 to $1.95 per share.
Business Wire
MINNEAPOLIS -- January 31, 2013
Xcel Energy Inc. (NYSE: XEL) today reported 2012 GAAP earnings of $905
million, or $1.85 per share compared with 2011 GAAP earnings of $841 million,
or $1.72 per share.
Ongoing earnings, which exclude one adjustment, were $1.82 per share for 2012
compared with $1.72 per share in 2011. Ongoing earnings increased largely due
to increases in electric margins driven by the conclusion of various rate
cases, which reflect our continued investment in our utility business and a
lower effective tax rate. Partially offsetting these positive factors were
warmer than normal winter weather, increases in depreciation expense,
operating and maintenance expenses and property taxes.
“We had an excellent year financially and operationally in 2012,” said Ben
Fowke, Chairman, President and Chief Executive Officer. “We delivered earnings
in the upper half of our guidance range, which represents the eighth
consecutive year in which we have met or exceeded our earnings guidance and
for the ninth consecutive year we increased our dividend. We implemented a
multi-year rate plan in Colorado and reached constructive regulatory outcomes
in several other rate cases. Finally, we maintained excellent reliability
during one of the warmest years on record, all executed with outstanding
safety performance.”
“We have established a solid strategy and continue to execute our business
plan. As a result, we are well positioned to deliver on our 2013 earnings
guidance of $1.85 to $1.95 per share,” stated Fowke.
Earnings Adjusted for Certain Items (Ongoing Earnings)
The following table provides a reconciliation of ongoing earnings per share to
GAAP earnings per share:
Three Months Ended Dec. 31 Twelve Months Ended Dec.
31
Diluted Earnings 2012 2011 2012 2011
Per Share
Ongoing^(a)
diluted earnings $ 0.29 $ 0.29 $ 1.82 $ 1.72
per share
Prescription drug - - 0.03 -
tax benefit ^(a)
GAAP ^ diluted $ 0.29 $ 0.29 $ 1.85 $ 1.72
earnings per share
^(a) See Note 6.
At 9:00 a.m. CST today, Xcel Energy will host a conference call to review
financial results. To participate in the call, please dial in 5 to 10 minutes
prior to the start and follow the operator’s instructions.
US Dial-In: (877) 941-0844
International Dial-In: (480) 629-9835
Conference ID: 4577479
The conference call also will be simultaneously broadcast and archived on Xcel
Energy’s website at www.xcelenergy.com. To access the presentation, click on
Investor Relations. If you are unable to participate in the live event, the
call will be available for replay from 2:00p.m. CST on Jan. 31 through
11:59p.m. CST on Feb. 1.
Replay Numbers
US Dial-In: (800) 406-7325
International Dial-In: (303) 590-3030
Access Code: 4577479 #
Except for the historical statements contained in this release, the matters
discussed herein, are forward-looking statements that are subject to certain
risks, uncertainties and assumptions. Such forward-looking statements,
including our 2013 earnings per share guidance and assumptions, are intended
to be identified in this document by the words “anticipate,” “believe,”
“estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,”
“project,” “possible,” “potential,” “should” and similar expressions. Actual
results may vary materially. Forward-looking statements speak only as of the
date they are made, and we do not undertake any obligation to update them to
reflect changes that occur after that date. Factors that could cause actual
results to differ materially include, but are not limited to: general economic
conditions, including inflation rates, monetary fluctuations and their impact
on capital expenditures and the ability of Xcel Energy Inc. and its
subsidiaries (collectively, Xcel Energy) to obtain financing on favorable
terms; business conditions in the energy industry, including the risk of a
slow down in the U.S. economy or delay in growth recovery; trade, fiscal,
taxation and environmental policies in areas where Xcel Energy has a financial
interest; customer business conditions; actions of credit rating agencies;
competitive factors, including the extent and timing of the entry of
additional competition in the markets served by Xcel Energy Inc. and its
subsidiaries; unusual weather; effects of geopolitical events, including war
and acts of terrorism; state, federal and foreign legislative and regulatory
initiatives that affect cost and investment recovery, have an impact on rates
or have an impact on asset operation or ownership or impose environmental
compliance conditions; structures that affect the speed and degree to which
competition enters the electric and natural gas markets; costs and other
effects of legal and administrative proceedings, settlements, investigations
and claims; actions by regulatory bodies impacting our nuclear operations,
including those affecting costs, operations or the approval of requests
pending before the Nuclear Regulatory Commission; financial or regulatory
accounting policies imposed by regulatory bodies; availability or cost of
capital; employee work force factors; and the other risk factors listed from
time to time by Xcel Energy in reports filed with the Securities and Exchange
Commission (SEC), including Risk Factors in Item 1A and Exhibit99.01 of Xcel
Energy Inc.’s Annual Report on Form10-K for the year ended Dec.31, 2011 and
Quarterly Reports on Form 10-Q for the quarters ended March 31, June 30 and
Sept. 30, 2012.
This information is not given in connection with any
sale, offer for sale or offer to buy any security.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(amounts in thousands, except per share data)
Three Months Ended Dec. 31 Twelve Months Ended Dec. 31
2012 2011 2012 2011
Operating
revenues
Electric $ 2,010,976 $ 1,988,800 $ 8,517,296 $ 8,766,593
Natural gas 520,513 560,109 1,537,374 1,811,926
Other 19,646 19,501 73,553 76,251
Total
operating 2,551,135 2,568,410 10,128,223 10,654,770
revenues
Operating
expenses
Electric fuel
and purchased 898,752 920,293 3,623,935 3,991,786
power
Cost of
natural gas 323,495 370,351 880,939 1,163,890
sold and
transported
Cost of sales 8,568 8,291 29,067 30,391
— other
Operating and
maintenance 599,917 565,130 2,176,095 2,140,289
expenses
Conservation
and demand
side 69,285 69,303 260,527 281,378
management
program
expenses
Depreciation
and 231,689 194,303 926,053 890,619
amortization
Taxes (other
than income 103,032 96,738 408,924 374,815
taxes)
Total
operating 2,234,738 2,224,409 8,305,540 8,873,168
expenses
Operating 316,397 344,001 1,822,683 1,781,602
income
Other income, 1,222 960 6,175 9,255
net
Equity
earnings of 7,821 7,714 29,971 30,527
unconsolidated
subsidiaries
Allowance for
funds used
during 18,336 12,533 62,840 51,223
construction —
equity
Interest
charges and
financing
costs
Interest
charges —
includes other
financing
costs of
$5,961,
$6,295,
$24,087 and 144,112 152,395 601,582 591,098
$24,019,
respectively
Allowance for
funds used
during (10,586 ) (6,606 ) (35,315 ) (28,181 )
construction —
debt
Total interest
charges and 133,526 145,789 566,267 562,917
financing
costs
Income from
continuing
operations 210,250 219,419 1,355,402 1,309,690
before income
taxes
Income taxes 70,042 78,478 450,203 468,316
Income from
continuing 140,208 140,941 905,199 841,374
operations
(Loss) income
from
discontinued (38 ) (432 ) 30 (202 )
operations,
net of tax
Net income 140,170 140,509 905,229 841,172
Dividend
requirements - - - 3,534
on preferred
stock
Premium on
redemption of - - - 3,260
preferred
stock
Earnings
available to $ 140,170 $ 140,509 $ 905,229 $ 834,378
common
shareholders
Weighted
average common
shares
outstanding:
Basic 488,428 486,223 487,899 485,039
Diluted 489,136 486,991 488,434 485,615
Earnings per
average common
share:
Basic $ 0.29 $ 0.29 $ 1.86 $ 1.72
Diluted 0.29 0.29 1.85 1.72
Cash dividends
declared per $ 0.27 $ 0.26 $ 1.07 $ 1.03
common share
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Earnings Release (Unaudited)
Due to the seasonality of Xcel Energy’s operating results, quarterly financial
results are not an appropriate base from which to project annual results.
The only common equity securities that are publicly traded are common shares
of Xcel Energy Inc. The earnings and earnings per share (EPS) of each
subsidiary discussed below do not represent a direct legal interest in the
assets and liabilities allocated to such subsidiary but rather represent a
direct interest in our assets and liabilities as a whole. EPS by subsidiary is
a financial measure not recognized under GAAP that is calculated by dividing
the net income or loss attributable to the controlling interest of each
subsidiary by the weighted average fully diluted Xcel Energy Inc. common
shares outstanding for the period. We use this non-GAAP financial measure to
evaluate and provide details of earnings results. We believe that this
measurement is useful to investors to evaluate the actual and projected
financial performance and contribution of our subsidiaries. This non-GAAP
financial measure should not be considered as an alternative to our
consolidated fully diluted EPS determined in accordance with GAAP as an
indicator of operating performance.
Note 1. Earnings Per Share Summary
The following table summarizes the diluted earnings per share for Xcel Energy:
Three Months Ended Dec. 31 Twelve Months Ended Dec.
31
Diluted Earnings 2012 2011 2012 2011
(Loss) Per Share
Public Service
Company of $ 0.16 $ 0.18 $ 0.90 $ 0.82
Colorado (PSCo)
NSP-Minnesota 0.13 0.11 0.70 0.73
Southwestern
Public Service 0.01 0.01 0.22 0.18
Company (SPS)
NSP-Wisconsin 0.02 0.02 0.10 0.10
Equity earnings
of 0.01 0.01 0.04 0.04
unconsolidated
subsidiaries
Regulated
utility — 0.33 0.33 1.96 1.87
continuing
operations ^(a)
Xcel Energy Inc. (0.04 ) (0.04 ) (0.14 ) (0.15 )
and other costs
Ongoing^(b)
diluted earnings 0.29 0.29 1.82 1.72
per share
Prescription
drug tax benefit - - 0.03 -
^(b)
GAAP diluted
earnings per $ 0.29 $ 0.29 $ 1.85 $ 1.72
share
^(a) See Note 2.
^(b) See Note 6.
PSCo — PSCo’s ongoing earnings increased $0.08 per share for 2012. The
increase is primarily due to an electric rate increase, effective May 2012,
and the impact of warmer summer weather. The increase was partially offset by
decreased wholesale revenue due to the expiration of a long-term power sales
agreement with Black Hills Corp, higher depreciation expense and operating and
maintenance (O&M) expenses.
NSP-Minnesota — NSP-Minnesota’s 2012 ongoing earnings decreased $0.03 per
share. The decrease is primarily due to the unfavorable impact of warmer than
normal winter weather during the first quarter, electric sales decline, higher
property taxes, higher O&M expenses and depreciation expense. These decreases
were partially offset by the 2012 rate increase and a lower effective tax
rate.
SPS — SPS’ ongoing earnings increased $0.04 per share for 2012. The increase
is the result of rate increases in New Mexico and Texas, effective January
2012, partially offset by the impact of milder weather during the second half
of the year, higher depreciation expense and property taxes.
NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings were flat for 2012. Ongoing
earnings were positively impacted by rate increases, effective January 2012,
offset by higher O&M expenses.
The following table summarizes significant components contributing to the
changes in the 2012 EPS compared with the same periods in 2011, which are
discussed in more detail later in the release.
Three Months Twelve Months
Diluted Earnings (Loss) Per Share Ended Dec. 31 Ended Dec. 31
2011 GAAP and ongoing^(a) diluted earnings $ 0.29 $ 1.72
per share
Components of change — 2012 vs. 2011
Higher electric margins 0.05 0.15
Lower effective tax rate 0.01 0.04
Lower conservation and DSM expenses - 0.03
(generally offset in revenues)
Higher AFUDC - Equity 0.01 0.02
Higher natural gas margins 0.01 0.01
Higher operating and maintenance expenses (0.04 ) (0.05 )
Higher depreciation and amortization (0.05 ) (0.04 )
Higher taxes (other than income taxes) (0.01 ) (0.04 )
Lower (higher) interest charges 0.01 (0.01 )
Other, net (including interest and premium 0.01 (0.01 )
on redemption of preferred stock)
2012 ongoing^(a) diluted earnings per 0.29 1.82
share
Prescription drug tax benefit ^(a) - 0.03
2012 GAAP diluted earnings per share $ 0.29 $ 1.85
^(a) See Note 6.
Note 2. Regulated Utility Results — Continuing Operations
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot
summers or cold winters increase electric and natural gas sales while,
conversely, mild weather reduces electric and natural gas sales. The estimated
impact of weather on earnings is based on the number of customers, temperature
variances and the amount of natural gas or electricity the average customer
historically uses per degree of temperature. Accordingly, deviations in
weather from normal levels can affect Xcel Energy’s financial performance,
from both an energy and demand perspective.
Degree-day or Temperature-Humidity Index (THI) data is used to estimate
amounts of energy required to maintain comfortable indoor temperature levels
based on each day’s average temperature and humidity. Heating degree-days
(HDD) is the measure of the variation in the weather based on the extent to
which the average daily temperature falls below 65° Fahrenheit, and cooling
degree-days (CDD) is the measure of the variation in the weather based on the
extent to which the average daily temperature rises above 65° Fahrenheit. Each
degree of temperature above 65° Fahrenheit is counted as one cooling
degree-day, and each degree of temperature below 65° Fahrenheit is counted as
one heating degree-day. In Xcel Energy’s more humid service territories, a THI
is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI
are most likely to impact the usage of Xcel Energy’s residential and
commercial customers. Industrial customers are less weather sensitive.
Normal weather conditions are defined as either the 20-year or 30-year average
of actual historical weather conditions. The historical period of time used in
the calculation of normal weather differs by jurisdiction based on the time
period used by the regulator in establishing estimated volumes in the rate
setting process. To calculate the impact of weather on demand, a demand factor
is applied to the weather impact on sales as defined above to derive the
amount of demand associated with the weather impact.
The percentage increase (decrease) in normal and actual HDD, CDD and THI are
provided in the following table:
Three Months Ended Dec. 31 Twelve Months Ended Dec. 31
2012 2011 2012 2012 2011 2012
vs. vs. vs. vs. vs. vs.
Normal Normal 2011 Normal Normal 2011
HDD (6.7 ) % (8.7 ) % 2.1 % (15.9 ) % (1.0 ) % (14.8 ) %
CDD N/A N/A N/A 46.1 38.1 5.7
^(a)
THI N/A N/A N/A 36.1 37.9 0.2
^(a)
^(a) CDD and THI have no meaningful impact on fourth quarter sales.
Weather — The following table summarizes the estimated impact of temperature
variations on EPS compared with sales under normal weather conditions:
Three Months Ended Dec. 31 Twelve Months Ended Dec. 31
2012 vs. 2011 vs. 2012 2012 vs. 2011 2012 vs.
vs. vs.
Normal Normal 2011 Normal Normal 2011
Retail $ (0.002 ) $ (0.006 ) $ 0.004 $ 0.081 $ 0.080 $ 0.001
electric
Firm
natural (0.003 ) (0.006 ) 0.003 (0.033 ) 0.002 (0.035 )
gas
Total $ (0.005 ) $ (0.012 ) $ 0.007 $ 0.048 $ 0.082 $ (0.034 )
In 2012, Xcel Energy refined its estimate to incorporate the impact of weather
on demand charges. As a result, the estimated weather impact on earnings per
share for prior periods has been adjusted for comparison purposes.
Sales Growth (Decline) — The following table summarizes Xcel Energy’s sales
growth (decline) for actual and weather-normalized sales in 2012:
Three Months Ended Dec. 31
Weather
Actual Normalized
Electric 0.5 % 0.0 %
residential
Electric
commercial (0.4 ) (0.4 )
and
industrial
Total retail
electric (0.2 ) (0.3 )
sales
Firm natural 0.0 (0.9 )
gas sales
Twelve Months Ended Dec.
31
Twelve Months Ended Dec. (Without Leap Day)
31
Weather Weather
Actual Normalized Actual Normalized
Electric (1.0 ) % (0.1 ) % (1.2 ) % (0.4 ) %
residential
Electric
commercial 0.1 0.0 (0.2 ) (0.2 )
and
industrial
Total retail
electric (0.3 ) 0.0 (0.5 ) (0.3 )
sales
Firm natural (10.6 ) (0.3 ) (11.0 ) (0.8 )
gas sales
Electric — Electric revenues and fuel and purchased power expenses are largely
impacted by the fluctuation in the price of natural gas, coal and uranium used
in the generation of electricity, but as a result of the design of fuel
recovery mechanisms to recover current expenses, these price fluctuations have
little impact on electric margin. The following table details the electric
revenues and margin:
Three Months Ended Dec. 31 Twelve Months Ended Dec. 31
(Millions of 2012 2011 2012 2011
Dollars)
Electric $ 2,011 $ 1,989 $ 8,517 $ 8,767
revenues
Electric fuel
and purchased (899 ) (920 ) (3,624 ) (3,992 )
power
Electric margin $ 1,112 $ 1,069 $ 4,893 $ 4,775
The following table summarizes the components of the changes in electric
margin:
Three Months Twelve Months
Ended Dec. 31 Ended Dec. 31
(Millions of Dollars) 2012 vs. 2011 2012 vs. 2011
Retail rate increases (Colorado, Texas,
New Mexico, Wisconsin, South Dakota,
North Dakota, Michigan and Minnesota) ^(a) $ 50 $ 125
Demand revenue 7 13
Transmission revenue, net of costs (7 ) 13
Conservation and DSM incentive (6 ) 12
Estimated impact of weather 4 1
Firm wholesale ^(b) (12 ) (48 )
Retail sales decrease, excluding weather (2 ) (6 )
impact
Conservation and DSM revenue (offset by 2 (5 )
expenses)
Other, net 7 13
Total increase in electric margin $ 43 $ 118
In the fourth quarter of 2011, NSP-Minnesota reduced depreciation
expense and revenues by approximately $30 million, representing a
full year of depreciation expense, based on the proposed rate case
^(a) settlements at that time. As a result, NSP-Minnesota recognized
higher revenues and depreciation expense, in the fourth quarter of
2012, of approximately $23 million. These settlement provisions did
not impact the year over year comparison.
^(b) Decrease is primarily due to the expiration of a long-term power
sales agreement with Black Hills Corp., effective Jan. 1, 2012.
Natural Gas — The cost of natural gas tends to vary with changing sales
requirements and the cost of natural gas purchases. However, due to the design
of purchased natural gas cost recovery mechanisms to recover current expenses
for sales to retail customers, fluctuations in the cost of natural gas have
little effect on natural gas margin. The following table details natural gas
revenues and margin:
Three Months Ended Dec. 31 Twelve Months Ended Dec. 31
(Millions of 2012 2011 2012 2011
Dollars)
Natural gas $ 521 $ 560 $ 1,537 $ 1,812
revenues
Cost of natural
gas sold and (323) (370) (881) (1,164)
transported
Natural gas $ 198 $ 190 $ 656 $ 648
margin
The following table summarizes the components of the changes in natural gas
margin:
Three Months Twelve Months
Ended Dec. 31 Ended Dec. 31
(Millions of Dollars) 2012 vs. 2011 2012 vs. 2011
Pipeline system integrity adjustment rider $ 7 $ 29
(Colorado) offset by expenses
Retail rate increase (Colorado, Wisconsin) - 16
Estimated impact of weather 2 (26 )
Conservation and DSM revenue (offset by (3 ) (17 )
expenses)
Other, net 2 6
Total increase in natural gas margin $ 8 $ 8
O&M Expenses — O&M expenses increased $34.8 million, or 6.2 percent, for the
fourth quarter of 2012 and $35.8 million, or 1.7 percent, for 2012, compared
with 2011. The following table summarizes the changes in O&M expenses:
Three Months Twelve Months
Ended Dec. 31 Ended Dec. 31
(Millions of Dollars) 2012 vs. 2011 2012 vs. 2011
Employee benefits $ (1 ) $ 36
Pipeline system integrity costs 5 20
SmartGridCity™ 11 11
Prairie Island Extended Power Uprate (EPU) 10 10
Plant generation costs (12 ) (17 )
Bad debt expense (2 ) (10 )
Labor and contract labor 10 (2 )
Other, net 14 (12 )
Total increase in O&M expenses $ 35 $ 36
*Higher employee benefits are mainly due to increased pension expense.
*Higher pipeline system integrity costs relate to increased compliance and
inspection initiatives, which in Colorado are recovered through the
pipeline system integrity rider.
*See Note 4 for further discussion of SmartGridCity and Prairie Island EPU.
*Lower plant generation costs are primarily attributable to fewer plant
overhauls in 2012.
*Higher fourth quarter labor and contract labor costs are largely driven by
vegetation management and substation maintenance.
Conservation and Demand Side Management (DSM) Program Expenses — Conservation
and DSM program expenses were flat for the fourth quarter of 2012 and
decreased $20.9 million, or 7.4 percent, for 2012, compared with 2011. The
lower expenses are primarily attributable to lower gas rider rates, as well as
the timing of recovery of electric conservation improvement program expenses
at NSP-Minnesota. Conservation and DSM program expenses are generally
recovered in our major jurisdictions concurrently through riders and base
rates.
Depreciation and Amortization — Depreciation and amortization increased $37.4
million, or 19.2 percent, for the fourth quarter of 2012 and $35.4 million, or
4.0 percent, for 2012, compared with 2011. NSP-Minnesota recognized higher
revenues and higher depreciation expense by approximately $23 million in the
fourth quarter of 2012, based on settlements in the Minnesota and South Dakota
electric rate cases, which resulted in a year-to-date adjustment lowering
depreciation and revenue in the fourth quarter of 2011. Overall, the increase
for 2012, compared to 2011 is primarily due to a portion of the Monticello
extended power uprate going into service in May 2011 at NSP-Minnesota, the
Jones Unit 3 going into service in June 2011 at SPS and normal system
expansion across Xcel Energy’s service territories.
Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased
$6.3 million, or 6.5 percent, for the fourth quarter of 2012 and $34.1
million, or 9.1 percent, for 2012, compared with 2011. The increases are due
to an increase in property taxes primarily in Minnesota. Higher property taxes
in Colorado related to the electric retail business are being deferred, based
on the multi-year rate settlement approved by the Colorado Public Utilities
Commission (CPUC) in May 2012.
Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC
increased $9.8 million for the fourth quarter of 2012 and $18.8 million for
2012, compared with 2011. The increases are primarily due to the expansion of
PSCo’s transmission facilities, additional construction related to the
Colorado Clean Air Clean Jobs Act (CACJA) and life extension work at the
Prairie Island nuclear generating plant.
Interest Charges — Interest charges decreased $8.3 million, or 5.4 percent,
for the fourth quarter of 2012 and increased $10.5 million, or 1.8 percent,
for 2012, compared with 2011. The overall increase is due to higher long-term
debt levels to fund investment in utility operations, partially offset by
lower interest rates.
Income Taxes — Income tax expense for continuing operations decreased $8.4
million for the fourth quarter of 2012, compared with the same period in 2011.
The decrease in income tax expense was primarily due to a decrease in pretax
income in 2012 and a tax benefit related to the reversal of a tax valuation
allowance in 2012. The effective tax rate for continuing operations was 33.3
percent for the fourth quarter of 2012 compared with 35.8 percent for the same
period in 2011. The lower effective tax rate for 2012 was primarily due to the
adjustment referenced above. The effective tax rate would have been 34.5
percent for the fourth quarter of 2012 without this tax benefit.
Income tax expense for continuing operations decreased $18.1 million for 2012,
compared with 2011. The decrease in income tax expense was primarily due to a
tax benefit of approximately $14.9 million associated with a carryback and a
tax benefit of $17 million related to the restoration of a portion of the tax
benefit written off in 2010 associated with federal subsidies for prescription
drug plans. These were partially offset by higher pretax income in 2012. The
effective tax rate for continuing operations was 33.2 percent for 2012
compared with 35.8 percent for 2011. The lower effective tax rate for 2012 was
primarily due to the adjustments referenced above. The effective tax rate
would have been 35.6 percent for 2012 without these tax benefits.
Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
Percentage
of Total
(Billions of Dollars) Dec. 31, 2012 Capitalization
Current portion of long-term debt $ 0.3 1 %
Short-term debt 0.6 3
Long-term debt 10.1 51
Total debt 11.0 55
Common equity 8.9 45
Total capitalization $ 19.9 100 %
Credit Facilities — As of Jan. 29, 2013, Xcel Energy Inc. and its utility
subsidiaries had the following committed credit facilities available to meet
liquidity needs:
(Millions of Facility Drawn^(a) Available Cash Liquidity Maturity
Dollars)
Xcel Energy $ 800.0 $ 351.0 $ 449.0 $ 0.2 $ 449.2 July
Inc. 2017
PSCo 700.0 169.0 531.0 1.1 532.1 July
2017
NSP-Minnesota 500.0 323.2 176.8 0.6 177.4 July
2017
SPS 300.0 35.0 265.0 0.9 265.9 July
2017
NSP-Wisconsin 150.0 41.0 109.0 0.1 109.1 July
2017
Total $ 2,450.0 $ 919.2 $ 1,530.8 $ 2.9 $ 1,533.7
^(a)Includes outstanding commercial paper and letters of credit.
Credit Ratings — Access to reasonably priced capital markets is dependent in
part on credit and ratings. The following ratings reflect the views of Moody’s
Investors Service (Moody’s), Standard& Poor’s Rating Services (Standard &
Poor’s), and Fitch Ratings (Fitch).
As of Jan. 29, 2013, the following represents the credit ratings assigned to
Xcel Energy Inc. and its utility subsidiaries:
Company Credit Type Moody's Standard & Fitch
Poor's
Xcel Energy Inc. Senior Unsecured Baa1 BBB+ BBB+
Debt
Xcel Energy Inc. Commercial Paper P-2 A-2 F2
NSP-Minnesota Senior Unsecured A3 A- A
Debt
NSP-Minnesota Senior Secured Debt A1 A A+
NSP-Minnesota Commercial Paper P-2 A-2 F2
NSP-Wisconsin Senior Unsecured A3 A- A
Debt
NSP-Wisconsin Senior Secured Debt A1 A A+
NSP-Wisconsin Commercial Paper P-2 A-2 F2
PSCo Senior Unsecured Baa1 A- A-
Debt
PSCo Senior Secured Debt A2 A A
PSCo Commercial Paper P-2 A-2 F2
SPS Senior Unsecured Baa2 A- BBB+
Debt
SPS Senior Secured Debt A3 A- A-
SPS Commercial Paper P-2 A-2 F2
The highest credit rating for debt is Aaa/AAA and the lowest investment grade
rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1
and the lowest rating is P-3/A-3/F-3. A security rating is not a
recommendation to buy, sell or hold securities. Ratings are subject to
revision or withdrawal at any time by the credit rating agency and each rating
should be evaluated independently of any other rating.
Capital Expenditures — The 2012 actual and the current estimated capital
expenditure programs of Xcel Energy Inc. and its subsidiaries for the years
2013 through 2017 are shown in the table below. The capital expenditure
forecast has been revised to reflect the termination of the Prairie Island
EPU.
Actual Forecast
(Millions of 2012 2013 2014 2015 2016 2017
Dollars)
By Subsidiary
NSP-Minnesota $ 1,018 $ 1,395 $ 1,135 $ 910 $ 925 $ 1,080
PSCo 887 1,075 1,000 850 800 840
SPS 389 490 400 305 300 345
NSP-Wisconsin 155 180 240 245 230 235
WYCO 1 15 - - - -
Total capital $ 2,450 $ 3,155 $ 2,775 $ 2,310 $ 2,255 $ 2,500
expenditures
By Function 2012 2013 2014 2015 2016 2017
Electric $ 772 $ 1,025 $ 710 $ 550 $ 465 $ 570
generation
Electric 734 1,010 870 650 635 770
transmission
Electric 486 515 525 525 535 545
distribution
Natural gas 247 355 365 335 325 320
Nuclear fuel 53 95 155 100 140 145
Other 158 155 150 150 155 150
Total capital $ 2,450 $ 3,155 $ 2,775 $ 2,310 $ 2,255 $ 2,500
expenditures
By Project 2012 2013 2014 2015 2016 2017
Other capital $ 1,720 $ 1,710 $ 1,610 $ 1,555 $ 1,600 $ 1,755
expenditures
PSCo CACJA 189 345 235 90 15 -
Other major
transmission 179 245 260 175 320 415
projects
CapX2020
transmission 170 350 295 140 - -
project
Natural gas
pipeline 100 140 170 190 130 135
replacement
Nuclear fuel 53 95 155 100 140 145
Nuclear
capacity
increases and 39 270 50 60 50 50
life
extension
Total capital $ 2,450 $ 3,155 $ 2,775 $ 2,310 $ 2,255 $ 2,500
expenditures
The capital expenditure programs of Xcel Energy are subject to continuing
review and modification. Actual utility construction expenditures may vary
from the estimates due to changes in electric and natural gas projected load
growth, regulatory decisions, legislative initiatives, reserve margins, the
availability of purchased power, alternative plans for meeting long-term
energy needs, compliance with future environmental requirements, renewable
portfolio standards, and merger, acquisition and divestiture opportunities to
support corporate strategies.
Financing — Xcel Energy issues debt and equity securities to refinance
retiring maturities, reduce short-term debt, fund construction programs,
infuse equity in subsidiaries, fund asset acquisitions and for other general
corporate purposes. The current estimated financing plans of Xcel Energy Inc.
and its subsidiaries for the years 2013 through 2017 are shown in the table
below. The financing plan has been revised to reflect the termination of the
Prairie Island EPU and the impacts of extended bonus depreciation under the
recent federal tax bill.
(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations* $ 10,150
New Debt** 2,045
Equity 400
DRIP 400
2013-2017 Capital Expenditures $ 12,995
Maturing Debt $ 1,793
* Cash from operations, net of dividend and pension funding.
** Reflects a combination of short and long-term debt.
During 2012, Xcel Energy Inc. and its utility subsidiaries completed the
following financings:
*In June, SPS issued $100 million of 30-year first mortgage bonds with a
coupon of 4.50 percent.
*In August, NSP-Minnesota issued $300 million of 10-year first mortgage
bonds with a coupon of 2.15 percent, and $500 million of 30-year first
mortgage bonds with a coupon of 3.40 percent.
*In September, PSCo issued $300 million of 10-year first mortgage bonds
with a coupon of 2.25 percent, and $500 million of 30-year first mortgage
bonds with a coupon of 3.60 percent.
*In October, NSP-Wisconsin issued $100 million of 30-year first mortgage
bonds with a coupon of 3.70 percent.
During 2013, Xcel Energy Inc. and its utility subsidiaries anticipate issuing
the following:
*NSP-Minnesota may issue approximately $400 million of first mortgage bonds
in the first half of 2013.
*PSCo may issue approximately $500 million of first mortgage bonds in the
first half of 2013.
*SPS may issue approximately $100 million of first mortgage bonds in the
first half of 2013.
Financing plans are subject to change, depending on capital expenditures,
internal cash generation, market conditions and other factors.
Note 4. Rates and Regulation
NSP-Minnesota – Minnesota 2012 Electric Rate Case — In November 2012,
NSP-Minnesota filed a request with the Minnesota Public Utilities Commission
(MPUC) for an increase in annual revenues of approximately $285 million, or
10.7 percent. The rate filing is based on a 2013 forecast test year, a
requested return on equity (ROE) of 10.6 percent, an average electric rate
base of approximately $6.3 billion and an equity ratio of 52.56 percent.
In December 2012, the MPUC accepted the filing as complete and approved the
interim rates of approximately $251 million, as requested, effective Jan. 1,
2013, subject to refund.
The procedural schedule is as follows:
*Intervenor Direct Testimony – Feb. 28, 2013
*Rebuttal Testimony – March 25, 2013
*Surrebuttal Testimony – April 12, 2013
*Evidentiary Hearing – April 18 – 24, 2013
*Initial Brief – May 15, 2013
*Reply Brief and Findings of Fact – May 30, 2013
*Administrative Law Judge (ALJ) Report – July 3, 2013
*MPUC Order – Anticipated by September 2013
Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a
Certificate of Need (CON) for an EPU project at the Prairie Island nuclear
generating plant. The total estimated cost of the EPU was $294 million, of
which approximately $77.6 million has been incurred, including AFUDC of
approximately $13.3 million. Subsequently, NSP-Minnesota filed a resource plan
update and a change of circumstances (COC) filing notifying the MPUC that
there were changes in the size, timing and cost estimates for this project,
revisions to economic and project design analysis and changes due to the
estimated impact of revised scheduled outages. The information indicated
reductions to the estimated benefit of the uprate project. As a result,
NSP-Minnesota concluded that further investment in this project would not
benefit customers. In December 2012, the MPUC voted unanimously that no party
had shown cause to prevent termination of the EPU CON. The MPUC is expected to
issue an order terminating the EPU CON in early 2013.
NSP-Minnesota plans to address recovery of incurred costs in the next rate
case for each of the NSP-Minnesota jurisdictions and to file a request with
the FERC for approval to recover a portion of the costs from NSP-Wisconsin
through the Interchange Agreement. NSP-Wisconsin plans to seek cost recovery
in a future rate case. Based on the outcome of the MPUC decision, EPU costs
incurred to date were compared to the discounted value of the estimated future
rate recovery based on past jurisdictional precedent, resulting in a $10.1
million pretax charge in December 2012.
NSP-Minnesota – North Dakota 2012 Electric Rate Case — In December 2012,
NSP-Minnesota filed a request with the North Dakota Public Service Commission
(NDPSC) for an increase in annual retail electric revenues of approximately
$16.9 million, or 9.25 percent. The rate filing is based on a 2013 forecast
test year, a requested ROE of 10.6 percent, an electric rate base of
approximately $377.6 million and an equity ratio of 52.56 percent.
In January 2013, the NDPSC approved an interim electric increase of $14.7
million, effective Feb. 16, 2013, subject to refund. A final NDPSC decision on
the case is expected in the third quarter of 2013.
NSP-Minnesota – South Dakota 2012 Electric Rate Case — In June 2012,
NSP-Minnesota filed a request with the South Dakota Public Utilities
Commission (SDPUC) to increase electric rates by $19.4 million annually. The
request was based on a 2011 historic test year adjusted for known and
measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an
average rate base of $367.5 million and an equity ratio of 52.89 percent.
In December 2012, the procedural schedule was suspended to allow time to
construct a potential settlement agreement between NSP-Minnesota and the SDPUC
Staff. Interim rates of $19.4 million went into effect on Jan. 1, 2013,
subject to refund. A SDPUC decision is expected in the first half of 2013.
NSP-Wisconsin – 2012 Electric and Gas Rate Case — In June 2012, NSP-Wisconsin
filed a request with the Public Service Commission of Wisconsin (PSCW) to
increase rates for electric and natural gas service, effective Jan. 1, 2013.
NSP-Wisconsin requested an overall increase in annual electric rates of $39.1
million, or 6.7 percent, and an increase in natural gas rates of $5.3 million,
or 4.9 percent.
The electric rate filing was based on a 2013 forecast test year, a ROE of
10.40 percent, an equity ratio of 52.50 percent and an average 2013 electric
rate base of approximately $788.6 million. The natural gas rate request was
solely due to a proposal to recover the initial costs associated with the
environmental cleanup of a site in Ashland, Wis.
In December 2012, the PSCW approved an electric rate increase of approximately
$35.5 million, or 6.1 percent, based on a 10.4 percent ROE and an equity ratio
of 52.50 percent. The PSCW also approved a natural gas rate increase of $2.7
million, or 2.5 percent, to begin recovering costs associated with the cleanup
in Ashland, Wis. Final rates were implemented on Jan. 1, 2013.
PSCo – Colorado 2012 Gas Rate Case — In December 2012, PSCo filed a
multi-year request with the Colorado Public Utilities Commission (CPUC) to
increase Colorado retail natural gas rates by $48.5 million in 2013 with
subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015.
PSCo also requested to increase Colorado retail steam rates by $1.6 million in
2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million
in 2015. Both requests are based on a 2013 forecast test year, a 10.5 percent
ROE, a rate base of $1.3 billion for natural gas and $21 million for steam and
an equity ratio of 56 percent. Final rates are expected to be effective in the
third quarter of 2013.
PSCo is requesting an extension of its Pipeline System Integrity Adjustment
(PSIA) rider mechanism to collect the costs of accelerated pipeline integrity
efforts, including system renewal projects. PSCo estimates that the PSIA will
increase by $26.8 million in 2014 with a subsequent step increase of $24.7
million in 2015 in addition to the proposed changes in base rate revenue. In
conjunction with the multi-year base rate step increases, PSCo is proposing a
stay-out provision and an earnings test through the end of 2015.
PSCo – SmartGridCity™ (SGC) Cost Recovery — PSCo requested recovery of the
revenue requirements associated with $45 million of capital and $4 million of
annual O&M costs incurred to develop and operate SGC as part of its 2010
electric rate case. In February 2011, the CPUC allowed recovery of
approximately $28 million of the capital cost and all of the O&M costs. In
December 2011, PSCo requested CPUC approval for the recovery of the remaining
capital investment in SGC and also provided the additional information
requested. On Jan. 17, 2013, the ALJ recommended denial of PSCo’s request for
recovery of the remaining portion of the SGC investment. Parties will have an
opportunity to appeal the ALJ’s recommended decision by filing exceptions with
the CPUC. If no exceptions are filed within 20 days, the recommended decision
will become effective. As a result of the ALJ’s recommended decision, PSCo
recognized a $10.7 million pre-tax charge in 2012, representing the net book
value of the disallowed investment.
PSCo Resource Plan — In July 2012, PSCo filed two separate applications to
update its resource plan. The first was an application to purchase Brush
Power, LLC and all of its assets including Brush generating Units 1, 3 and 4
for a total purchase price of approximately $75 million. The Brush units
currently provide 237 MW of natural gas fueled capacity and energy to PSCo
under Purchased Power Agreements (PPAs) that are set to expire in 2017 for
Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4.
The second application sought approval to retire Arapahoe Unit 4, a 109 MW
coal-fired company-owned generating station at the end of 2013. This was
presented as an alternative to permanently fuel switching Arapahoe Unit 4 to
natural gas and instead replacing the capacity and associated energy with a
natural gas PPA with an existing generator.
In September 2012, the FERC approved the acquisition of Brush Power, LLC.
However, in December 2012, the CPUC denied approval of the acquisition in oral
deliberations due to the risks associated with the transaction. PSCo has the
ability to terminate the transaction based on the regulatory outcome. The CPUC
also denied PSCo’s proposal to retire Arapahoe 4 by the end of 2013; however,
this proposal could be revisited.
SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an
electric rate case in Texas with the Public Utility Commission of Texas for an
increase in annual revenue of approximately $90.2 million. The rate filing is
based on a historic twelve month test year ended June 30, 2012 adjusted for
known and measurable changes, a requested ROE of 10.65 percent, an electric
rate base of $1.15 billion and an equity ratio of 52 percent.
The procedural schedule is as follows:
*Intervenor Direct Testimony – Feb. 22, 2013
*Staff Direct Testimony – March 1, 2013
*SPS Rebuttal Testimony – March 15, 2013
*Hearing Starts – March 26, 2013
*The procedural order also establishes July 1, 2013 as the latest date
rates from this case will become effective.
SPS – New Mexico 2012 Electric Rate Case — In December 2012, SPS filed an
electric rate case in New Mexico with the New Mexico Public Regulation
Commission (NMPRC) for an increase in annual revenue of approximately $45.9
million. The rate filing is based on a 2014 forecast test year, a requested
ROE of 10.65 percent, a jurisdictional electric rate base of $365.5 million
and an equity ratio of 53.89 percent. A NMPRC decision is expected in the
fourth quarter of 2013 with the implementation of final rates anticipated in
the first quarter of 2014.
Note 5. Xcel Energy Earnings Guidance
Xcel Energy’s 2013 earnings guidance is $1.85 to $1.95 per share. Key
assumptions related to 2013 earnings are detailed below:
*Constructive outcomes in all rate case and regulatory proceedings.
*Normal weather patterns are experienced for the year.
*Weather-adjusted retail electric utility sales are projected to grow
approximately 0.5 percent.
*Weather-adjusted retail firm natural gas sales are projected to decline by
approximately 1 percent.
*Rider revenue recovery for certain projects have been rolled into base
rates, therefore the change is no longer meaningful.
*O&M expenses are projected to increase approximately 4 percent to 5
percent over 2012 levels.
*Depreciation expense is projected to increase $75 million to $85 million
over 2012 levels.
*Property taxes are projected to increase approximately $35 million to $40
million over 2012 levels.
*Interest expense (net of AFUDC — debt) is projected to decrease $30
million to $35 million from 2012 levels.
*AFUDC — equity is projected to increase approximately $15 million to $20
million over 2012 levels.
*The effective tax rate is projected to be approximately 34 percent to 36
percent.
*Average common stock and equivalents are projected to be approximately 490
million to 500 million shares.
Note 6. Non-GAAP Reconciliation
Xcel Energy’s management believes that ongoing earnings provide a meaningful
comparison of earnings results and is representative of Xcel Energy’s
fundamental core earnings power. Xcel Energy’s management uses ongoing
earnings internally for financial planning and analysis, for reporting of
results to the Board of Directors, and when communicating its earnings outlook
to analysts and investors.
The following table provides a reconciliation of ongoing earnings to GAAP
earnings:
Three Months Ended Dec. 31 Twelve Months Ended Dec. 31
(Thousands of 2012 2011 2012 2011
Dollars)
Ongoing ^ $ 140,208 $ 140,941 $ 888,255 $ 841,374
earnings
Prescription
drug tax - - 16,944 -
benefit
Total
continuing 140,208 140,941 905,199 841,374
operations
(Loss) income
from (38 ) (432 ) 30 (202 )
discontinued
operations
GAAP ^ $ 140,170 $ 140,509 $ 905,229 $ 841,172
earnings
Impact of the Patient Protection and Affordable Care Act — In March 2010, the
Patient Protection and Affordable Care Act was signed into law. The law
includes provisions to generate tax revenue to help offset the cost of the new
legislation. One of these provisions reduces the deductibility of retiree
health care costs to the extent of federal subsidies received by plan sponsors
that provide retiree prescription drug benefits equivalent to Medicare Part D
coverage, beginning in 2013. Xcel Energy expensed approximately $17 million of
previously recognized tax benefits relating to the federal subsidies during
the first quarter of 2010.
In the third quarter of 2012, Xcel Energy implemented a tax strategy related
to the allocation of funding of Xcel Energy’s retiree prescription drug plan.
This strategy restored a portion of the tax benefit associated with federal
subsidies for prescription drug plans that had been accrued since 2004 and was
expensed in 2010. As a result, Xcel Energy recognized approximately $17
million of income tax benefit.
XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (Unaudited)
(amounts in thousands, except per share data)
Three Months Ended Dec. 31
2012 2011
Operating revenues:
Electric and natural gas revenues $ 2,531,489 $ 2,548,909
Other 19,646 19,501
Total operating revenues 2,551,135 2,568,410
Income from continuing operations 140,208 140,941
Loss from discontinued operations (38 ) (432 )
Net income $ 140,170 $ 140,509
Earnings available to common $ 140,170 $ 140,509
shareholders
Weighted average diluted common shares 489,136 486,991
outstanding
Components of Earnings per Share —
Diluted
Regulated utility — continuing $ 0.33 $ 0.33
operations
Xcel Energy Inc. and other costs (0.04 ) (0.04 )
Ongoing^(a) diluted earnings per share 0.29 0.29
Prescription drug tax benefit ^(a) - -
GAAP diluted earnings per share $ 0.29 $ 0.29
Twelve Months Ended Dec. 31
2012 2011
Operating revenues:
Electric and natural gas revenues $ 10,054,670 $ 10,578,519
Other 73,553 76,251
Total operating revenues 10,128,223 10,654,770
Income from continuing operations 905,199 841,374
Income (loss) from discontinued 30 (202 )
operations
Net income $ 905,229 $ 841,172
Earnings available to common $ 905,229 $ 834,378
shareholders
Weighted average diluted common shares 488,434 485,615
outstanding
Components of Earnings per Share —
Diluted
Regulated utility — continuing $ 1.96 $ 1.87
operations
Xcel Energy Inc. and other costs (0.14 ) (0.15 )
Ongoing^(a) diluted earnings per share 1.82 1.72
Prescription drug tax benefit ^(a) 0.03 -
GAAP ^ diluted earnings per share $ 1.85 $ 1.72
Book value per share $ 18.19 $ 17.44
^(a) See Note 6.
Contact:
Xcel Energy Inc.
Paul Johnson, 612-215-4535
Vice President, Investor Relations and Financial Management
or
Jack Nielsen, 612-215-4559
Director, Investor Relations
or
Cindy Hoffman, 612-215-4536
Senior Investor Relations Analyst
or
For news media inquiries only:
Xcel Energy Media Relations, 612-215-5300
Xcel Energy internet address: www.xcelenergy.com